ISO New England Inc. February /19 ICR Related Values 1

Transcription

1 ISO New England Installed Capacity Requirement, Local Sourcing Requirements and Capacity Requirement Values for the System-Wide Capacity Demand Curve for the 2018/19 Capacity Commitment Period ISO New England Inc. February /19 ICR Related Values 1

2 ISO New England Installed Capacity Requirement, Local Sourcing Requirements, and Capacity Requirement Values for the System-Wide Capacity Demand Curve for the 2018/19 Capacity Commitment Period Executive Summary As part of the Forward Capacity Market (FCM), ISO New England Inc. (ISO-NE) conducts a Forward Capacity Auction (FCA) three years in advance of each Capacity Commitment Period (CCP) to meet the region s resource adequacy needs. The latest FCA, conducted on February 2, 2015, resulted in capacity (megawatts) commitments of sufficient quantities to meet the Installed Capacity Requirement (ICR) for the 2018/19 CCP. The 2018/19 CCP is the ninth CCP of the FCM (FCA9) and it begins on June 1, 2018 and ends on May 31, This report documents the assumptions and simulation results of the 2018/19 CCP ICR, Local Sourcing Requirements (LSR) and Capacity Requirement Values for the System Wide Capacity Demand Curve calculations (collectively referred to as the ICR Related Values ), all of which are key inputs in FCA9, along with the Hydro-Québec Interconnection Capability Credits (HQICCs), which are also a key input into the calculation of the ICR. For the 2018/19 CCP, ISO-NE has identified three Load Zones that are importconstrained and as a result, modeled as Capacity Zones in FCA9. These Capacity Zones are: Connecticut, Northeast Massachusetts/Boston (NEMA/Boston) and the combined Load Zones of Southeastern Massachusetts and Rhode Island (SEMA/RI). 1 Therefore, the ICR Related Values for FCA9 consider three LSR values. The Maine Load Zone, which was modeled as an export-constrained Capacity Zone in prior FCAs, was determined not to be export-constrained. In fact, no Load Zones were considered to be export-constrained. Therefore the ICR Related Values for FCA9 do not consider any Maximum Capacity Limit (MCL) values. In a filing, dated April 1, 2014, ISO-NE filed Market Rules relating to a System-Wide Capacity Demand Curve (Demand Curve) which was used for the first time in FCA9. 2 The Demand Curve has capacity requirement values which were calculated at the cap and foot 3 of the curve and are considered and filed as part of the ICR Related Values. 1 The FERC filing identifying SEMA/RI as a Capacity Zone is available at: 000_5_8_14_iso_zone_boundry.pdf. 2 The filing is available at: 3 The design of the Demand Curve is specified in Section III of the Market Rules which describes the cap as the Capacity Requirement Value at LOLE, Max[1.6 x Net CONE,CONE] and the foot of the Demand Curve of Capacity Requirement Value at LOLE, $0. See Figure 2 for the FCA9 Demand Curve. 2018/19 ICR Related Values 1

3 As detailed below, ISO-NE has calculated an ICR of 35,142 MW. This value accounts for tie benefits (emergency energy assistance) assumed obtainable from New Brunswick (Maritimes), New York and Québec of 1,970 MW, in aggregate, but it does not reflect a reduction in capacity requirements relating to HQICCs. The HQICC value of 953 MW per month is applied to reduce the portion of the ICR that is allocated to the Interconnection Rights Holders (IHR). Thus, the net amount of capacity to be purchased within the FCA to meet the ICR, after deducting the HQICC value of 953 MW per month, is 34,189 MW. The LSR values associated with FCA9 for the Connecticut, NEMA/Boston and SEMA/RI Capacity Zones are 7,331 MW, 3,572 MW and 7,479 MW, respectively. As stated previously, there were no export-constrained zones modeled and as such, no MCL values were needed for FCA9. Section III.12.1 of Market Rule 1 states that the Demand Curve will be calculated using the same methodology as the ICR calculation. The ISO shall determine, by applying the same modeling assumptions and methodology used in determining the Installed Capacity Requirement, the capacity requirement value for each LOLE probability specified in Section III for the System-Wide Capacity Demand Curve. As such, the capacity requirements at the Demand Curve cap and foot, calculated at a 1 day in 5 years (1-in-5) Loss of Load Expectation (LOLE), and a 1 day in 87 years (1-in- 87) LOLE are 33,132 MW and 37,027 MW, respectively. As in past years, ISO-NE developed the initial ICR recommendation with stakeholder input, which was provided in part through the NEPOOL committee processes through review by NEPOOL s Power Supply Planning Committee (PSPC) during the course of four meetings, by the NEPOOL Reliability Committee (RC) at its September 16, 2014 meeting and by the NEPOOL Participants Committee (PC) at its October 3, 2014 meeting. 4 In addition, the New England States Committee on Electricity (NESCOE) provided feedback on the proposed ICR Related Values at the relevant NEPOOL committee meetings. Representatives of NESCOE provided feedback at discussions of the ICR Related Values assumptions at the PSPC and were in attendance for the RC and PC meetings at which the ICR Related Values for FCA9 were discussed and voted. After the NEPOOL committee voting process was completed, ISO-NE filed the ICR Related Values and HQICCs for the 2018/19 FCA with the FERC in a filing dated 4 All of the load and resource assumptions needed for the General Electric Multi-Area Simulation ( GE MARS ) model used to calculate tie benefits and the ICR Related Values were reviewed by the PSPC, a subcommittee of the NEPOOL Reliability Committee (RC). The NEPOOL Load Forecast Committee (LFC), also a subcommittee of the NEPOOL Reliability Committee, reviews the load forecast assumptions and methodology. 2018/19 ICR Related Values 2

4 November 4, January 2, The FERC accepted the ICR Related Values in a letter dated Table 1 shows the ICR Related Values for the 2018/19 CCP. The monthly values for the HQICCs are provided in Table 2. Table 1: Summary of 2018/19 ICR Related Values (MW) 7,8 2018/19 FCA New England Connecticut NEMA/ Boston SEMA/RI Peak Load (50/50) 30,005 7,725 6,350 5,910 Existing Capacity Resources 32,842 9,239 3,868 6,984 Installed Capacity Requirement 35,142 NET ICR (ICR Minus 953 MW HQICCs) 34,189 Capacity Requirement at 1-in-5 LOLE 33,132 Capacity Requirement at 1-in-87 LOLE 37,027 Local Sourcing Requirements 7,331 3,572 7,479 Table 2: Monthly HQICCs (MW) 2018/19 CCP Month Jun-18 Jul-18 Aug-18 Sep-18 Oct-18 Nov-18 Dec-18 Jan-19 Feb-19 Mar-19 Apr-19 May-19 HQICC Values The ISO-NE filing is located at _ _ _icr_filing.pdf. 6 The FERC Order accepting the ICR Values for the 2018/19 FCA is available at: 7 After reflecting a reduction in capacity requirements relating to the 953 MW of HQICCs that are allocated to the Interconnection Rights Holders (IHR), the net amount of capacity to be procured within the Forward Capacity Auction to meet the ICR is the Net ICR value of 34,189 MW. 8 Existing Capacity Resource value for New England excludes HQICCs. 2018/19 ICR Related Values 3

5 Table of Contents Executive Summary... 1 Table of Contents... 4 List of Tables... 5 List of Figures... 6 Introduction... 7 Summary of ICR Related Values and Components for 2018/ Stakeholder Process Methodology Reliability Planning Model for ICR Related Values Installed Capacity Requirement (ICR) Calculation Local Sourcing Requirements (LSR) Calculation Local Resource Adequacy (LRA) Requirement Transmission Security Analysis (TSA) Calculation Methodology for Calculating the TSA Local Sourcing Requirement (LSR) Maximum Capacity Limit (MCL) Calculation Assumptions Load Forecast Load Forecast Uncertainty Existing Capacity Resources Generating Resources Intermittent Power Resources Demand Resources Import Resources Export Bids New Capacity Resources Resources Used to Calculate Locational Requirements Transmission Transfer Capability External Transmission Transfer Capability External Transmission Interface Availability Internal Transmission Transfer Capability OP-4 Load Relief Tie Benefits % Voltage Reduction Operating Reserve Proxy Units Summary Availability Generating Resource Forced Outages Generating Resource Scheduled Outages Intermittent Power Resource Availability Demand Resources Availability Difference from 2017/18 FCA ICR Related Values /19 ICR Related Values 4

6 List of Tables Table 1: Summary of 2018/19 ICR Related Values (MW)... 3 Table 2: Monthly HQICCs (MW)... 3 Table 3: ICR Related Values and Components for 2018/19 (MW)... 8 Table 4: Variables Used to Calculate ICR and Demand Curve (MW) Table 5: LRA Requirement Calculation Details (MW) Table 6: TSA Calculation Details (MW) Table 7: LSR for the 2018/19 CCP (MW) Table 8: Indicative MCL for the Maine Load Zone Calculation Details (MW) Table 9: Summer 2018 Peak Load Forecast Distribution (MW) Table 10: Existing Qualified Generating Capacity by Load Zone (MW) Table 11: Existing IPR by Load Zone (MW) Table 12: Existing Demand Resources by Load Zone (MW) Table 13: Existing Import Resources (MW) Table 14: Capacity Exports (MW) Table 15: Resources Used in the LSR Calculations (MW) Table 16: Transmission Transfer Capability of New England External Interfaces Modeled in the Tie Benefits Study (MW) Table 17: External Interface Outage Rates (% and Weeks) Table 18: Internal Transmission Transfer Capability Modeled in the LSR Calculations (MW),, Table 19: Capacity Imports Used to Adjust Tie Benefits by External Interface (MW) Table 20: 2018/19 Tie Benefits (MW) Table 21: 2018/19 versus 2017/18 Tie Benefits (MW) Table 22: OP-4 Action 6 & 8 Modeled (MW) Table 23: Summary of Resource and OP-4 Assumptions (MW) Table 24: Generating Resource EFORd (%) and Maintenance Weeks by Resource Category Table 25: Passive Demand Resources Summer (MW) and Availability (%) Table 26: Demand Response Resources Summer (MW) and Availability (%) Table 27: Summary of ICR Input Assumptions for 2018/19 vs. 2017/ Table 28: Assumed 5-Year Average % EFORd Weighted by Summer Ratings for 2018/19 versus 2017/18 ICR Calculations Table 29: Comparison of Demand Resources (MW) & Performance (%) for 2018/19 versus 2017/18 ICR Calculations Table 30: Summary of Changes in LRA Requirement for 2018/19 vs. 2017/ Table 31: Comparison of the TSA Requirement Calculation for 2018/19 vs. 2017/18 (MW) Table 32: Comparison of all ICR Related Values (MW) /19 ICR Related Values 5

7 List of Figures Figure 1: Formula for Annual Resulting Reserve Margin (%)... 8 Figure 2: System-Wide Capacity Demand Curve for 2018/19 (FCA9) Figure 3: Formula for ICR Calculation Figure 4: Formula for LRA Calculation Figure 5: Surplus Capacity Adjustment in Rest of New England Figure 6: Formula for TSA Requirements Figure 7: Formula for MCL Calculation Figure 8: Summarization of the Tie Benefits Calculation Process Figure 9: Formula for Calculating 5% Voltage Reduction Assumption Figure 10: Determining the Proxy Unit Size to Use in ICR Models /19 ICR Related Values 6

8 Introduction The Installed Capacity Requirement (ICR) is a measure of the installed resources that are projected to be necessary to meet both ISO New England s (ISO-NE) and the Northeast Power Coordination Council s (NPCC) reliability standards 9, with respect to satisfying the peak demand forecast for the New England Balancing Authority area while maintaining required reserve capacity. More specifically, the ICR is the amount of resources (MWs) needed to meet the reliability requirements defined for the New England Balancing Authority area of disconnecting non-interruptible customers (a loss of load expectation or LOLE ), on average, no more than once every ten years (an LOLE of 0.1 days per year). This criterion takes into account: other possible levels of peak electric loads due to weather variations, the impacts of resource availability, and the potential load and capacity relief obtainable through the use of ISO New England Operating Procedure No. 4 Actions During a Capacity Deficiency (OP-4). 10 This report discusses the derivation of the ICR, Local Sourcing Requirements (LSR) and the capacity requirement values for the System-Wide Capacity Demand Curve ( Demand Curve ) (collectively, the ICR Related Values ) 11, along with the Hydro-Québec Interconnection Capability Credits (HQICCs) for the 2018/19 CCP s Forward Capacity Auction (FCA) conducted on February 2, The 2018/19 CCP starts on June 1, 2018 and ends on May 31, This report documents the general process and methodology used for developing the assumptions utilized in calculating the ICR, including assumptions about load, resource capacity values and availability, load relief from OP-4, and transmission interface transfer capabilities and the methodology used for calculating the ICR. Also discussed are the calculation of LSR for import-constrained Load Zones, including the Local Resource Adequacy (LRA) Requirements and Transmission Security Analysis (TSA) Requirements that are inputs into the calculation of LSR along with the calculation of the MCL for export-constrained Capacity Zones which were not required as part of FCA9. In general, the methodology used for calculating the ICR Related Values for the 2018/19 FCA remains unchanged from the methodology used for calculating the prior ICR Related Values for the 2017/18 FCA, with the exception of the additional calculation of the capacity requirements for the Demand Curve, which was used for the first time in FCA9. 9 Information on the NPCC Standards is available at: 10 ISO-NE OP-4 is located at: 11 For FCA9, no zones were determined to be export-constrained and therefore, no Maximum Capacity Limit (MCL) values were filed as part of FCA /19 ICR Related Values 7

9 Summary of ICR Related Values and Components for 2018/19 Table 3 documents the ICR Related Values and components relating to the calculation of ICR. Table 3: ICR Related Values and Components for 2018/19 (MW) /19 FCA New England Connecticut NEMA/ Boston SEMA/RI Peak Load (50/50) 30,005 7,725 6,350 5,910 Existing Capacity Resources 32,842 9,239 3,868 6,984 Installed Capacity Requirement 35,142 NET ICR (ICR Minus 953 MW HQICCs) 34,189 Capacity Requirement at 1-in-5 LOLE 33,132 Capacity Requirement at 1-in-87 LOLE 37,027 Local Sourcing Requirements 7,331 3,572 7,479 The 35,142 MW ICR value does not reflect a reduction in capacity requirements relating to HQICCs that are allocated to the Interconnection Rights Holders (IRH) in accordance with Section III of Market Rule 1. After deducting the monthly HQICC value of 953 MW, the net Installed Capacity Requirement for use in the 2018/19 FCA is 34,189 MW, which is described as the Net ICR. The 34,189 MW of Net ICR, which excludes HQICCs, results in an Annual Resulting Reserve Margin value of 13.9%. The Annual Resulting Reserve Margin is a measure of the amount of resources potentially available in excess of the 50/50 seasonal peak load forecast value and is calculated as: Figure 1: Formula for Annual Resulting Reserve Margin (%) Annual Resulting Reserve Margin (%) = ((ICR-HQICCs-Annual 50/50 Peak Load) / (Annual 50/50 Peak Load)) x 100 The 13.9% Annual Resulting Reserving Margin is a slight increase from the 13.6% value calculated for the 2017/18 FCA. While some changes in ICR assumptions decreased the reserve margin, some do cause it to increase, particularly assumptions related to an increase in the generator forced outage rates. Overall, the net change in reserve margin was small. The increase in generator unavailability and other changes, along with the 12 Existing Capacity Resource value for New England excludes HQICCs. 2018/19 ICR Related Values 8

10 overall change in ICR, is discussed in more detail in the last section of this report, Difference from the 2017/18 FCA ICR Related Values. The capacity requirement values for the Demand Curve, calculated for the first time for FCA9 require that: The ISO shall determine, by applying the same modeling assumptions and methodology used in determining the Installed Capacity Requirement, the capacity requirement value for each LOLE probability specified in Section III for the System-Wide Capacity Demand Curve according to Section III.12.1 of Market Rule 1. As such, the capacity requirement values at the Demand Curve cap and foot, calculated at 1 day in 5 years (1-in-5) Loss of Load Expectation (LOLE), and at 1 day in 87 years (1- in-87) LOLE are 33,132 MW and 37,027 MW, respectively. The coordinates of the Demand Curve use a price quantity for the Cost of New Entry (CONE) into the capacity market. This price quantity is determined as max [1.6 times Net CONE, CONE]. CONE for the FCA for the 2018/19 CCP is $14.04/kW-month while Net CONE is $11.08/kW-month. 13 Using the coordinates of the cap of the Demand Curve of [Capacity Requirement Value at 1-in-5 LOLE, 1.6 x Net CONE ($17.728] and the foot of the Demand Curve of [Capacity Requirement Value at 1-in-87 LOLE, $0], the Demand Curve for FCA9 is shown in Figure The determination of CONE for 2018/19 was discussed at the March 12, 2014 Markets Committee: e_group_demand_curve_net_cone_final_proposal_03_12_14.pptx. For rules relating to CONE, see Market Rule 1 III /19 ICR Related Values 9

11 30,000 31,000 32,000 33,000 34,000 35,000 36,000 37,000 38,000 Price ($) Figure 2: System-Wide Capacity Demand Curve for 2018/19 (FCA9) $20 Net ICR $15 $10 $5 $0 Capacity Requirement (MW) A summary of historical ICR Related Values, including links to documentation and filings for FCA9 and prior years are available on the ISO-NE website under System Planning > Installed Capacity Requirements > Summary of Historical ICR Values (EXCEL Spreadsheet) and can be directly accessed at this link: /19 ICR Related Values 10

12 Stakeholder Process As in past years, ISO-NE developed the initial ICR recommendation with stakeholder input, which was provided in part through the NEPOOL committee process with review by NEPOOL s Power Supply Planning Committee (PSPC) during the course of four meetings. The PSPC, which is chaired by ISO-NE, is a non-voting, technical subcommittee reporting to the NEPOOL Reliability Committee (RC). Most PSPC members are representatives of NEPOOL Participants. The PSPC assists ISO-NE with the development of resource adequacy based requirements such as the ICR, LSR, MCL and Demand Curve capacity requirements, including the appropriate load and resource assumptions for modeling expected power system conditions. As part of the stakeholder voting process, the ICR Related Values was vetted through the RC at its September 16, 2014 meeting and acted on by the NEPOOL Participants Committee (PC) at its October 3, 2014 meeting. 14 Representatives of the New England States Committee on Electricity ( NESCOE ) provided feedback on the proposed ICR Related Values at the relevant NEPOOL PSPC, RC and PC meetings, and were in attendance for the meetings at which the ICR Related Values for the 2018/19 Forward Capacity Auction were discussed and voted. At the September 16, 2014 meeting of the RC, a motion to recommend support of the ICR Related Values passed by a show of hands, with four opposed (1 Transmission Sector, 1 Publicly Owned Sector, and 2 Supplier Sector) and one abstention (1 Transmission Sector). A motion that the RC recommend that the PC support the HQICC values passed by a show of hands, with two opposed (2 Supplier Sector) and one abstention (1 Supplier Sector). At the October 3, 2014 PC meeting, the ICR Related Values and HQICC Values were removed as part of the Consent Agenda due to concerns by some Stakeholders that ISO- NE failed to recognize a present and continuing investment in renewable distributed generation resources. 15 Specifically they believed the load forecast, as an input into the ICR Related Values, should be decreased by an appropriate forecast of photovoltaic resources in the 2018/19 CCP. The vote on ICR Related Values subsequently failed at the PC All of the load and resource assumptions needed for the General Electric Multi-Area Simulation (GE MARS) model used to calculate tie benefits and the ICR Related Values were reviewed by the PSPC, a subcommittee of the NEPOOL RC. The NEPOOL Load Forecast Committee (LFC), also a subcommittee of the NEPOOL RC, reviews the load forecast assumptions and methodology. 15 The memo is part of the October 3, 2014 PC Meeting materials at 16 At the PC, the vote on the FCA9 ICR Related Values failed with a 38.61% vote in favor (Generation 17.17%, Transmission 0%; Supplier 15.60%; Alternative Resources 4.28%; Publicly Owned Entity 0%; and End User 1.56%). 2018/19 ICR Related Values 11

13 ISO-NE filed the ICR Related Values and HQICCs for the 2018/19 FCA with the FERC on November 4, The FERC accepted the ICR Related Values in a letter dated January 2, A copy of the filing is available at: _ _ _icr_filing.pdf. 18 The FERC Order accepting the ICR Values for the 2018/19 FCA is available at: /19 ICR Related Values 12

14 Methodology Reliability Planning Model for ICR Related Values The ICR is the minimum level of capacity required to meet the reliability requirements defined for the New England Balancing Authority area. This requirement is documented in Section 2 of ISO New England Planning Procedure No. 3, 19 Reliability Standards for the New England Area Bulk Power Supply System, which states: Resources will be planned and installed in such a manner that, after due allowance for the factors enumerated below, the probability of disconnecting noninterruptible customers due to resource deficiency, on the average, will be no more than once in ten years. Compliance with this criterion shall be evaluated probabilistically, such that the loss of load expectation (LOLE) of disconnecting non-interruptible customers due to resource deficiencies shall be, on average, no more than 0.1 day per year. Included as variables within the reliability model are: a. The possibility that load forecasts may be exceeded as a result of weather variations. b. Immature and mature equivalent forced outage rates appropriate for resources of various sizes and types, recognizing partial and full outages. c. Due allowance for generating unit scheduled outages and deratings. d. Seasonal adjustments of resource capability. e. Proper maintenance requirements. f. Available operating procedures. g. The reliability benefits of interconnections with systems that are not Governance Participants. h. Such other factors as may be appropriate from time to time. The ICR for the 2018/19 CCP was established using the General Electric Multi-Area Reliability Simulation Model (GE MARS). GE MARS is a computer program that uses a sequential Monte Carlo simulation to probabilistically compute the resource adequacy of a bulk electric power system by simulating the random behavior of both loads and resources. For the ICR calculation, the GE MARS model is used as a one-bus model and the New England transmission system is assumed to have no constraints within this simulation. In other words, all the resources modeled are assumed to be able to deliver their full output to meet forecast load requirements. To calculate the expected days per year that the bulk electric system would not have adequate resources to meet peak demands and required reserves, the GE MARS Monte Carlo process repeatedly simulates the year using multiple replications and evaluates the impacts of a wide-range of possible random combinations of resource outages. 19 Available at: /19 ICR Related Values 13

15 Chronological system histories are developed by combining randomly generated operating histories of the resources serving the hourly chronological demand. For each hour, the program computes the isolated area margins based on the available capacity and demand within each area. The program collects the statistics for computing the reliability indices and then proceeds to the next hour to perform the same type of calculation. After simulating all of the hours in the year, the program computes the annual indices and tests for convergence. If the simulation has not converged to an acceptable level, it proceeds to another replication of the study year. Installed Capacity Requirement (ICR) Calculation The formula for calculating the New England ICR is: Figure 3: Formula for ICR Calculation Installed Capacity Capacity Tie Benefits OP4 Load Relief Requirement ( ICR) ALCC 1 APk HQICCs Where: APk = Annual 50/50 Peak Load Forecast for summer Capacity = Total Capacity (sum of all supply and demand resources) Tie Benefits = Tie Reliability Benefits OP-4 Load Relief = Load relief from ISO-NE OP-4 - Actions 6 & 8 and the modeling of the minimum 200 MW Operating Reserve limit ALCC = Additional Load Carrying Capability (as determined by the % of peak load) HQICCs = Monthly HQICC value 20 The ICR formula is designed such that the results identify the minimum amount of capacity required to meet New England s resource adequacy criterion of expecting to interrupt non-interruptible load, on average, no more than once every ten years. If the system is more reliable than the resource adequacy criterion (i.e., the system LOLE is less than or equal to 0.1 days per year), additional resources are not required, and the ICR is determined by increasing loads (Additional Load Carrying Capability or ALCC) so that New England s LOLE is exactly at 0.1 days per year. For the 2018/19 CCP, the New England system, using the resources that qualified as Existing Capacity, is less reliable than the resource adequacy criterion requirement. Therefore, additional capacity in the form of proxy units is needed within the model. Proxy units are used if existing capacity resources are insufficient to meet the resource adequacy planning criterion, as provided by Section III of Market Rule 1. Proxy units are assigned availability characteristics such that when proxy resources are used in place of all the resources assumed to be available to the system, the resulting system LOLE remains unchanged from that calculated using the existing resources. The use of proxy units to meet the 20 In the ICR calculation, the HQICCs are treated differently than other resources; they are not adjusted by the ALCC amount. 2018/19 ICR Related Values 14

16 system LOLE criterion is intended to neutralize the size and availability impact of unknown resource additions on the ICR. Prior to the calculation of ICR Related Values for the 2018/19 CCP, ISO-NE conducted a study to update the size and availability characteristics of the proxy units used in the analysis. 21 In the study, proxy unit characteristics are determined using the average system availability and a series of LOLE calculations. Using these characteristics gives a proxy unit that when added to the model, does not increase or decrease ICR. For more details on the proxy unit characteristics, see the section of this report entitled Proxy Units. To determine the ICR for the 2018/19 CCP, four proxy units were needed in addition to the existing capacity within the ICR model. In addition, for the 1-in-5 LOLE and the 1- in-87 LOLE capacity requirements calculations for the Demand Curve, one proxy unit was needed and14 proxy units were needed, respectively. Table 4 shows the details of the variables used to calculate the ICR for the 2018/19 CCP. Table 4: Variables Used to Calculate ICR and Demand Curve (MW) Total Capacity Breakdown 1-in-5 LOLE 2018/19 FCA ICR 1-in-87 LOLE Generating Resources 29,829 29,829 29,829 Tie Benefits 1,970 1,970 1,970 Imports/Sales (41) (41) (41) Demand Resources 3,054 3,054 3,054 OP4 - Action 6 & 8 (Voltage Reduction) Minimum Reserve Requirement (200) (200) (200) Proxy Unit Capacity 400 1,600 4,400 Total Capacity 35,453 36,653 39,453 Installed Capacity Requirement Calculation Details 1-in-5 LOLE 2018/19 FCA ICR 1-in-87 LOLE Annual Peak 30,005 30,005 30,005 Total Capacity 35,453 36,653 39,453 Tie Benefits 1,970 1,970 1,970 HQICCs OP4 - Action 6 & 8 (Voltage Reduction) Minimum Reserve Requirement (200) (200) (200) ALCC Installed Capacity Requirements 34,085 35,142 37,980 Net ICR 33,132 34,189 37,027 Reserve Margin without HQICCs 10.4% 13.9% 23.4% Local Sourcing Requirements (LSR) Calculation The methodology for calculating LSR for import-constrained Capacity Zones involves calculating the amount of resources located within the Capacity Zone that would meet 21 Study results presented at the May 22, 2014 PSPC Meeting: y_unit_2014_study.pdf. 2018/19 ICR Related Values 15

17 both a local criterion requirement called the Local Resource Adequacy (LRA) Requirement and a transmission security criterion called the Transmission Security Analysis (TSA) Requirement. The TSA Requirement is an analysis that ISO-NE uses to maintain operational reliability when reviewing de-list bids of resources within the FCM auctions. The system must meet both resource adequacy and transmission security requirements; therefore, the LSR for an import-constrained zone is the amount of capacity needed to satisfy the higher of either (i) the LRA or (ii) the TSA Requirement. Local Resource Adequacy (LRA) Requirement The LRA Requirements are calculated using the same assumptions for forecasted load and resources as those used within the calculation of the ICR. To determine the locational requirements of the system, the LRA Requirements are calculated using the multi-area reliability model, GE MARS, according to the methodology specified in Section III.12.2 of Market Rule 1. The LRA Requirements are calculated using the value of the firm load adjustments and the existing resources within the zone, including any proxy units that were added as a result of the total system not meeting the LOLE criteria. Because the LRA Requirement is the minimum amount of resources that must be located within a zone to meet the system reliability requirements, for a zone with excess capacity, the process to calculate this value involves shifting capacity out of the zone under study until the reliability threshold, or target LOLE, is achieved. Shifting capacity, however, may lead to skewed results, since the load carrying capability of various resources are not homogeneous. For example, one megawatt of capacity from a nuclear power plant does not necessarily have the same load carrying capability as one megawatt of capacity from a wind turbine. Consequently, in order to model the effect of shifting generic capacity, firm load is shifted. Specifically, as one megawatt of load is added to an import-constrained zone, a megawatt of load is subtracted from the rest of New England, thus keeping the entire system load constant. The load that was shifted must be subtracted from the total resources (including proxy units) to determine the minimum amount of resources that are required in that zone. Before the shifted load is subtracted, it is first converted to equivalent capacity by using the average resource-unavailability rate within the zone. Thus, the LRA Requirement is calculated as the existing resources in the zone including any proxy units, minus the unavailability-adjusted firm load adjustment. As this load shift test is being performed over a transmission interface internal to the New England Balancing Authority Area, an allowance for transmission-related LOLE must also be applied. This transmission-related LOLE allowance is days per year and is only applied when determining the LRA Requirement of a Capacity Zone. An LOLE of days per year is the point at which it becomes clear that the remaining resources within the zone under study are becoming insufficient to satisfy local capacity requirements. Further reduction in local resources would cause the LOLE in New England to rapidly increase above the criterion. 2018/19 ICR Related Values 16

18 For each import-constrained transmission Capacity Zone, the LRA Requirement is calculated using the following methodology, as outlined in Market Rule 1, Section III : a) Model the Capacity Zone under study and the Rest of New England area using the GE MARS simulation model, reflecting load and resources (supply & demandside) electrically connected to them, including external Balancing Authority area support from tie benefits. b) If the system LOLE is less than 0.1 days/year, firm load is added (or unforced capacity is subtracted) so that the system LOLE equals 0.1 days/year. c) Model the transmission interface constraint between the Load Zone under study and the Rest of New England. d) Add proxy units, if required, within the ISO-NE Balancing Authority Area to meet the resource adequacy planning criterion of once in 10 year disconnection of non-interruptible customers. If the system LOLE with proxy units added is less than 0.1 days/year, firm load is added (or unforced capacity is subtracted) so that the system LOLE equals 0.1 days/year. Proxy units are modeled as stated in Section III of Market Rule 1. e) Adjust the firm load within the Capacity Zone under study until the LOLE of the ISO-NE Balancing Authority Area reaches days per year LOLE. As firm load is added to (or subtracted from) the Capacity Zone under study, an equal amount of firm load is removed from (or added to) the Rest of New England. The LRA Requirement is then calculated using the formula: 2018/19 ICR Related Values 17

19 Figure 4: Formula for LRA Calculation LRAZ Resources Z Proxy Units Z Firm Load Adjustment 1 FOR Z Z Where LRA z = Local Resource Adequacy Requirement for Capacity Zone Z. Resources z = MW of resources (supply & demand-side) electrically located within Load Zone Z, including Import Capacity Resources on the import-constrained side of the interface, if any and excludes HQICCs. Proxy Units z = MW of proxy unit additions, if needed, in Capacity Zone Z. Firm Load Adjustment z = MW of firm load added within Capacity Zone Z to make the LOLE of the New England Balancing Authority area equal to days per year. FOR z = Capacity weighted average of the forced outage rate modeled for all resources (supply & demand-side) within Capacity Zone Z, including any proxy unit additions to Capacity Zone Z. In addition, when performing the LRA calculation for the Rest of New England area used in the calculation of local requirements for export-constrained zones, the surplus capacity adjustment used to bring the system to the 0.1 days per year reliability criterion is also included in the calculation as: Figure 5: Surplus Capacity Adjustment in Rest of New England Surplus Capacity Adjustment 1 FOR Z Where: Surplus Capacity Adjustment z = MW of firm load added within Zone Z to make the LOLE of the New England Balancing Authority area equal to 0.1 days per year Table 5 shows the details of the LRA Requirement calculation for the 2018/19 CCP. Table 5: LRA Requirement Calculation Details (MW) Transmission Security Analysis (TSA) Calculation The TSA is a deterministic reliability screen of a transmission import-constrained area and is a security review as defined within Section 3 of ISO New England Planning Procedure No. 3, Reliability Standards for the New England Area Bulk Power Supply System and within Section 5.4 of Northeast Power Coordinating Council s (NPCC) Z Connecticut NEMA/Boston SEMA/RI Resource z [1] 9,239 3,868 6,984 Proxy Units z [2] Firm Load Adjustment z [4] 1, FOR z [5] LRA z [5]=[1]+[2]-([3]/(1-[4])) 7,268 3,129 7, /19 ICR Related Values 18

20 Regional Reliability Reference Directory #1, Design and Operation of the Bulk Power System. 22 The TSA review determines the requirements of the sub-area in order to meet its load through internal generation and import capacity. It is performed via a series of discrete transmission load flow study scenarios. In performing the analysis, static transmission interface transfer limits are established as a reasonable representation of the transmission system s capability to serve sub-area demand with available existing resources. The results are then presented in the form of a deterministic operable capacity analysis. In accordance with ISO New England Planning Procedure No. 3 and NPCC s Regional Reliability Reference Directory #1, the TSA includes evaluations of both: (1) the loss of the most critical transmission element and the most critical generator (Line-Gen), and (2) the loss of the most critical transmission element followed by loss of the next most critical transmission element (Line-Line). These deterministic analyses are currently used each day by ISO-NE System Operations to assess the amount of capacity required to be committed day-ahead within import-constrained Capacity Zones. Further, such deterministic sub-area transmission security analyses have consistently been used for reliability review studies performed to determine whether a resource seeking to retire or de-list would cause a violation of the reliability criteria. Figure 6 shows the formula used in the calculation of TSA requirements. Figure 6: Formula for TSA Requirements TSA Requirement (Need Import Limit) 1 - ( Assumed Unavailable Capacity / Existing Resources) Where: Need = Import Limit = Assumed Unavailable Capacity = Existing Resources = Load + Loss of Generator ( Line-Gen scenario), or Load + Loss of Import Capability (going from an N-1 Import Capability to an N-1-1 Import Capability; Line-Line scenario) Assumed transmission import limit Amount of assumed resource unavailability applied by de-rating capacity Amount of Existing Capacity Resources within the Zone Methodology for Calculating the TSA The system conditions used for the TSA analysis within the FCM are documented in Section 6 of ISO New England Planning Procedure No. 10, Planning Procedure to Support the Forward Capacity Market. 23 For the calculation of ICR, LRA and TSA, the bulk of the assumptions are the same. However, due to the deterministic and 22 A copy can be found at %20Design%20and%20Operation%20of%20the%20Bulk%20Power%20System%20%20Clean%20April %2020%202012%20GJD.pdf. 23 Available at: /19 ICR Related Values 19

21 transmission security-oriented nature of the TSA, some of the assumptions for calculating the TSA requirement differ from the assumptions used in determining the LRA Requirement. The differences are as follows: the assumed loads for the TSA are the 90/10 peak loads for the Connecticut, Boston and combined SEMA and Rhode Island sub-areas 24 for the 2018/19 CCP, whereas for LRA calculations, a distribution of loads covering the range of possible peak loads for that CCP is used. In addition, for the TSA, the forced outage of fast-start (peaking) generation is based on an assumed value of 20% instead of being based on historical five-year average generating unit performance. Finally, the load and capacity relief obtainable from actions of ISO-NE OP-4, with the exception of Demand Resources (which are treated as capacity resources), is not assumed within TSA calculations. Table 5 shows the details of the TSA requirement calculation for the Connecticut, NEMA/Boston, and SEMA/RI Capacity Zones. Table 6: TSA Calculation Details (MW) Connecticut NEMA/Boston SEMA/RI 2014 Sub-area 90/10 Load* 8,415 6,835 6,465 Reserves (Largest unit or loss of import capability) 1,225 1, Sub-area Transmission Security Need 9,640 8,247 7,165 Sub-area Existing Resources 9,239 3,868 6,984 Assumed Unavailable Capacity Sub-area N-1 Import Limit 2,950 4, Sub-area Available Resources 11,381 8,528 7,047 TSA Requirement = ( )/(1-808/9239) ( )/(1-190/3868) ( )/(1-723/6984) = 7,331 = 3,572 = 7,116 Local Sourcing Requirement (LSR) The LSR is determined as the higher of the LRA Requirement or TSA Requirement for the respective Capacity Zone. Table 7 summarizes the LRA and TSA for the Connecticut, NEMA/Boston and SEMA/RI Capacity Zones. As shown, the LRA is the highest requirement for the SEMA/RI Capacity Zone while the TSA is the highest requirement for the Connecticut and NEMA/Boston Capacity Zones. Therefore, the LSR for the Connecticut, NEMA/Boston and SEMA/RI Capacity Zones are 7,331 MW, 3,572 MW and 7,479 MW, respectively. 24 The combined Connecticut, Southwest Connecticut and Norwalk sub-areas, the Boston sub-area, and the combined Southeastern Massachusetts and Rhode Island sub-area load forecast and resources are used as proxies for the Connecticut, NEMA/Boston and SEMA/RI Capacity Zones load forecast and resources since the transmission transfer capability of the interfaces used in the respective LSR calculations are determined based on the 13 sub-area system representations used within ISO-NE s Regional System Plan (RSP). 2018/19 ICR Related Values 20

22 Table 7: LSR for the 2018/19 CCP (MW) Transmission Security Local Resource Analysis Adequacy Local Sourcing Capacity Zone Requirements Requirements Requirements Connecticut 7,331 7,268 7,331 NEMA/Boston 3,572 3,129 3,572 SEMA/RI 7,116 7,479 7,479 Maximum Capacity Limit (MCL) Calculation For the 2018/19 CCP, no zones were considered to be export-constrained; therefore an MCL was not filed for any Capacity Zones. An indicative MCL was calculated for the Maine Load Zone as part of the Capacity Zone Trigger Analysis, which determines if a Load Zone is either import or export-constrained and therefore modeled as a Capacity Zone in an FCA. This section of the Report details the calculation of the indicative MCL for the Maine Load Zone for the 2018/19 CCP. To determine the MCL, the New England ICR and the LRA for the Rest of New England need to be identified. Given that the ICR is the total amount of resources that need to be procured within New England, and the LRA requirement for the Rest of New England is the minimum amount of resources required for that area to satisfy its reliability criterion; the difference between the two is the maximum amount of resources that can be purchased within an export-constrained Load Zone. The indicative MCL for Maine includes qualified capacity resource imports over the New Brunswick ties (if relevant for a particular CCP) and also reflects the tie benefits assumed available over the New Brunswick ties. That is, the MCL is reduced to reflect the energy flows required to receive the assumed tie benefits from the Maritimes to assist the ISO- NE Balancing Authority Area at a time of a capacity shortage. Allowing more purchases of capacity from resources located in Maine could preclude the energy flows required to realize tie benefits. For an export-constrained transmission Capacity Zone, the MCL is calculated using the following method as described in Market Rule 1, Section III : a) Model the Capacity Zone under study and the Rest of New England area using the GE MARS simulation model, reflecting load and resources (supply & demandside) electrically connected to them, including external Balancing Authority area support from tie benefits. b) If the system LOLE is less than 0.1 days/year, firm load is added (or unforced capacity is subtracted) so that the system LOLE equals 0.1 days/year. 2018/19 ICR Related Values 21

23 c) Model the transmission interface constraint between the Capacity Zone under study and the Rest of New England area. d) Add proxy units, if required, within the ISO-NE Balancing Authority Area to meet the resource adequacy planning criterion of once in 10 years of disconnection of non-interruptible customers. If the system LOLE with proxy units added is less than 0.1 days/year, firm load is added (or unforced capacity is subtracted) so that the system LOLE equals 0.1 days/year. e) Adjust the firm load within the Rest of New England area until the LOLE of the Rest of New England area reaches days per year LOLE. As firm load is added to (or subtracted from) the Rest of New England area, an equal amount of firm load is removed from (or added to) the Capacity Zone under study. The MCL is then calculated using the formula: Figure 7: Formula for MCL Calculation MCL Y Net ICR - LRARest of New England Where MCL Y = Maximum Capacity Limit for Load Zone Y Net ICR = MW of Net ICR LRA Rest of New England = MW of Local Resource Adequacy Requirement for the Rest of New England area, which for the purposes of this calculation is treated as an import-constrained region, determined in accordance with Market Rule 1, Section III Table 8 shows the details of the indicative MCL for the Maine Load Zone calculation for the 2018/19 CCP. This value was not filed with the FERC as part of the ICR Related Values as Maine was not determined to be a Capacity Zone. Table 8: Indicative MCL for the Maine Load Zone Calculation Details (MW) 2018/19 FCA ICR for New England [1] 34,189 LRA RestofNewEngland [2] 30,275 Maximum Capacity Limit Y [3]=[1]-[2] 3, /19 ICR Related Values 22

24 Assumptions Load Forecast For each state in New England, ISO-NE develops a forecast distribution of typical daily peak loads for each week of the year based on each week s historical weather distribution combined with an econometrically estimated monthly model of typical daily peak demands. Each weekly distribution of typical daily peak demands includes the full range of daily peaks that could occur over the full range of weather experienced within that week along with their associated probabilities. The load forecast models for each of the six New England states were estimated using thirteen years of historical weekday daily peaks, the weather conditions at the time of the daily peak, a seasonal relationship that captures the change in peak demand response to weather over time, and a seasonal relationship that captures the change in peak demand response to base energy demand (and therefore economic and demographic factors) over time. The weather response relationships are forecast to grow at their historical rates but are adjusted for expected changes in electric appliance saturations. The base load relationships are forecasted to grow at the same rate as the associated energy forecast. The weather is represented by over forty years of historically-based weekly regional weather. The energy forecast for each state is econometrically estimated using forecasts of the real price of electricity and either real income or real gross state product. For purposes of determining the load forecast, ISO-NE Balancing Authority Area s load is defined as the sum of the load of each of the six New England states, calculated as described above. The forecasted load for the Connecticut Capacity Zone is the forecasted load for the state of Connecticut. The forecasted load for the NEMA/Boston Capacity Zone is developed using a load share ratio of the NEMA/Boston load to the forecasted load for the entire state of Massachusetts. The load share ratio is based on detailed bus load data from the network model for NEMA/Boston, as compared to the entire state of Massachusetts. The forecasted load for the SEMA portion of the SEMA/RI Capacity Zone is developed using the same load share ratio methodology as NEMA/Boston, while the RI portion is the load forecast for the state of Rhode Island. The overall New England and individual sub-area load forecasts used in the calculation of ICR Related Values for the 2018/19 CCP are documented within the 2014 Forecast Report of Capacity, Energy, Loads and Transmission (CELT Report). 25 Load Forecast Uncertainty GE MARS models the load forecast using hourly chronological sub-area loads and can include the effects of load forecast uncertainty by calculating the LOLE for up to ten different load levels and computes a weighted-average value based on the input 25 Located on ISO-NE s website at: /19 ICR Related Values 23

25 probabilities. Load forecast uncertainty multipliers are then used to account for load uncertainty related to weather. These are the per unit multipliers used for computing the loads used to calculate the reliability indices. Each per unit multiplier represents a load level, which is assigned a probability of that load level occurring. The mean, or 1.0 multiplier, represents the 50/50 forecast for peak load. These uncertainty multipliers are allowed to vary by month. The summer 2018 peak load forecast distribution is shown in Table 9. The values range from the 10 th percentile, representing peak loads with a 90% chance of being exceeded, to the 95 th percentile peak load, which represent peak loads having only a 5% chance of being exceeded. The median (50/50) of the forecast distribution is termed the expected value because the realized level is equally likely to fall either above or below that median value. The median value is reported to facilitate comparisons, but the inherently uncertain nature of the load forecast is modeled by the load forecast uncertainty multipliers used as an input to the GE MARS Model. Table 9: Summer 2018 Peak Load Forecast Distribution (MW) Year 10/90 20/80 30/70 40/60 50/50 60/40 70/30 80/20 90/10 95/5 2018/19 29,045 29,275 29,510 29,935 30,005 30,310 30,860 31,310 32,430 33,120 Existing Capacity Resources Market Rule 1, Section III details what shall be modeled within the ICR Related Values calculations as capacity, as defined by the following: (a) All Existing Generating Capacity Resources, (b) Resources cleared in previous Forward Capacity Auctions or obligated for the relevant Capacity Commitment Period, (c) All Existing Import Capacity Resources backed by a multi-year contract(s) to provide capacity into the New England Balancing Authority area, where that multi-year contract requires delivery of capacity for the Commitment Period for which the Installed Capacity Requirement is being calculated, and (d) Existing Demand Resources that are qualified to participate in the Forward Capacity Market and New Demand Resources that have cleared in previous Forward Capacity Auctions and obligated for the relevant Capacity Commitment Period and Other Demand Resources in existence during the ICAP Transition Period. Section III also states that the rating of the Existing Generating Capacity Resources, Existing Demand Resources and Existing Import Capacity Resources used in the calculation of the ICR Related Values shall be the summer Qualified Capacity value of such resources for the relevant zone. The Qualified Capacity value is based on a fiveyear median capacity rating for each resource. 2018/19 ICR Related Values 24